1. Field of the Invention
This invention relates generally to the field of seismic prospecting and, more particularly, to a method for deriving reservoir lithology and fluid content by stochastic inversion of seismic data.
2. Background of the Art
In the oil and gas industry, seismic prospecting techniques are commonly used to aid in the search for and evaluation of subterranean hydrocarbon deposits. Generally, a seismic energy source is used to generate a seismic signal which propagates into the earth and is at least partially reflected by subsurface seismic reflectors (i.e., interfaces between underground formations having different elastic properties). The reflections are recorded by seismic detectors located at or near the surface of the earth, in a body of water, or at known depths in boreholes, and the resulting seismic data may be processed to yield information relating to the geologic structure and properties of the subsurface formations.
The goal of seismic data processing is to extract from the data as much information as possible regarding the subsurface formations. Data processing techniques have been developed which typically permit the geologic structure of the subsurface formations to be determined with a great deal of accuracy. However, to date, efforts to develop techniques for deriving the fluid content of the subsurface formations have met with only limited success.
It is well known by persons skilled in the art of seismic prospecting that the presence of hydrocarbon accumulations in a subsurface formation can have a significant effect on the velocity of propagation of compressional waves (P-waves) through that formation. This effect is the basis of the so-called “bright spot” phenomenon in which an anomalously high reflection amplitude on a seismic section is an indication of the presence of hydrocarbon accumulations, particularly natural gas, in the formation. Unfortunately, the bright spot phenomenon is susceptible to error because many seismic amplitude anomalies are not caused by hydrocarbon accumulations, or they are caused by hydrocarbon accumulations which are low in total saturation and often non-commercial. For this reason, wells drilled on such bright spots often encounter either no reservoir sands at all (and, therefore, no hydrocarbons), or if the sands are present, no hydrocarbons or only low saturations of hydrocarbons.
One technique which may be useful for this purpose is amplitude variation with offset (“AVO”) analysis. In AVO analysis, measurements of P-wave reflection amplitudes with different angles of incidence are used to attempt to determine compressional wave (P-wave) velocity, shear wave (S-wave) velocity, density, and Poisson's ratio for each subsurface layer suspected of containing natural gas. Knowledge of these subsurface elastic properties can be used to predict whether or not natural gas accumulations are present. See e.g., Ostrander, W. J., “Plane-wave reflection coefficients for gas sands at non-normal angles of incidence,” Geophysics, v. 49, pp. 1637-1648, 1984, for a discussion of AVO analysis. Ostrander proposes a method for using AVO analysis to distinguish between gas-related amplitude anomalies and non-gas-related amplitude anomalies. However, Ostrander admits that distinguishing between low gas saturation and full saturation can be very difficult.
AVO techniques have been the subject of a number of prior patents. For example, U.S. Pat. No. 4,858,200 to Goins (“the Goins '200 patent”) discloses a method for determining the presence of hydrocarbons in subsurface geological formations by comparative assessment of P-wave and S-wave reflection data. The S-wave reflection data is estimated from the P-wave data using variations in the amplitude of the gathered P-wave data with source-receiver offset. Two related patents, U.S. Pat. Nos. 4,858,201 to Goins et al. (“the Goins '201 patent”), and 4,858,202 to Fitch et al. describe two different methods which can be used for obtaining S-wave data from common depth point gathered P-wave traces.
U.S. Pat. No. 4,817,060 to Smith discloses a process for directly detecting the presence of hydrocarbons from seismic data. First, the P-wave and S-wave reflectivities are extracted from the data on a trace-by-trace basis. The P-wave reflectivity is then determined as a function of the S-wave reflectivity and the result is subtracted from the extracted P-wave reflectivity to define a fluid factor which is indicative of the presence of hydrocarbons.
U.S. Pat. No. 5,001,677 to Masters discloses methods for processing and displaying seismic data to emphasize potential hydrocarbon bearing strata. These methods treat measured attributes from the seismic data as components of a vector, estimate a background vector which represents uninteresting geologic behavior, and then form at least one new attribute which quantifies departures from this uninteresting behavior.
The end products of these prior art AVO processes usually are predictions of the P-wave and S-wave reflectivities for the target location. Although some of these prior processes have recognized the desirability of also determining the density reflectivity (see e.g., the patents to Smith and Masters cited above), none has disclosed a method for successfully doing so.
Another technique which may be useful in discriminating between different lithologies and fluid saturations is pre-stack inversion based on either a one-dimensional (1D) or two-dimensional (2D) model of the earth's subsurface. See e.g., Symes, W. W. and Carazzone, J. J., “Velocity inversion by differential semblance optimization,” Geophysics, v. 56, pp. 654-663, 1991, and Liao, Quingbo. and McMechan, G. A., “Multifrequency viscoacoustic modeling and inversion,” Geophysics, v. 61, pp. 1371-1378, 1996.
As will be well known to persons skilled in the art, seismic inversion is a process for deriving a model of the earth's subsurface from seismic reflection data. First, the process attempts to extract information regarding the elastic properties of the subsurface from the data. This information is then used to construct a mathematical or physical model of the earth's subsurface, and synthetic seismograms are generated based on the model. If the synthetic seismograms do not compare favorably to the data, appropriate adjustments are made to the model, and new synthetic seismograms are generated for comparison with the data. This process repeats until the synthetic seismograms generated from the model approximate the actual data. The model is then accepted as accurate.
Pre-stack inversion processes typically attempt to estimate both the background P-wave velocity model and the contrast in various elastic parameters (P-wave velocity, S-wave velocity, and density) and, therefore, are non-linear. Thus, these techniques are extremely complex.
U.S. Pat. No. 5,583,825 to Carrazzone et al. describes a method for deriving reservoir lithology and fluid content for a target location from pre-stack seismic reflection data. The method uses inversion of pre-stack seismic reflection data for both the target location and a calibration location having known subsurface lithology and fluid content to derive the subsurface lithology and fluid content at the target location. The inversion process is preferably a viscoelastic inversion to account for the effects of friction on seismic wave propagation. The results of the inversion process are a set of subsurface elastic parameters for both the target and calibration locations. Relative magnitudes of these subsurface elastic parameters are compared, together with the known subsurface lithology and fluid content at the calibration location, to derive the subsurface lithology and fluid content at the target location.
The method of Carrazzone, while giving results superior to those in earlier techniques, still requires an inversion of seismic data and still carries out a two step procedure. In the first step, an inversion of the pre-stack seismic reflection data is carried out to determine the selected set of elastic parameters at each of a plurality of points in the models of the subsurface target and calibration locations. In the second step, the relative magnitudes of the elastic parameters for the subsurface target and calibration locations are compared; and using the results of the comparison and the known lithology and fluid content at the subsurface calibration location the lithology and fluid content at the subsurface target location are derived.
A problem with all of the prior art methods is the two step procedure, explicit or implicit, used for obtaining fluid properties. There inversion of seismic data to obtain reflection coefficients (or elastic parameters) is by itself difficult. The second step of determination of fluid properties from reflection coefficients requires an inversion procedure that is very sensitive to the unknown parameters being determined. A variety of parameters must be used and some of these parameters must be obtained outside the inversion itself. It would be desirable to have a robust method of determination of fluid parameters of subsurface formations that also takes into account the relative uncertainty in knowledge of subsurface rock formations. The present invention satisfies this need.